Stratigraphic entrapment of oil in carbonate is a function of petrophysics of the reservoir and trap rock. These petrophysical characteristics can be observed from sample examination without extensive laboratory measurements.

Petrophysics is an essential addition to the physical measurements of total porosity and permeability routinely collected from reservoir rock samples. Total porosity is a ratio of the rock's void space to its bulk volume. Under subsurface reservoir conditions, this porosity is occupied by fluid of two phases. Commonly the non-wetting oil phase occupies this porosity according to the size and distribution of the rock's pore system. The displacement of interstitial water by oil depends on the size of pore throats. That part not effectively displaced by oil remains as irreducible water saturation within the reservoir. These reservoir properties can be determined from capillary pressure measurements conducted in the laboratory. The capillary pressure curves may be investigated by the same statistical methods used on cumulative curves from sieve analysis of unconsolidated sands.

Seven distinctive petrophysical characteristics were evident from 200 samples of Williston basin carbonate rocks studied. These characteristics may be classified by effective porosity, displacement pressure, and pore distribution. Representative examples from this study show good and intermediate reservoir rock as well as reservoir-trap rock. The concept of low effective porosity can explain high water-cut production from carbonate reservoirs.